This invention relates to methods and apparatus for evaluating the condition of oilfield tubular goods and the state of deterioration of subsurface pipe or casing. More specifically, this invention relates to methods to determine whether corrosion present in the oilfield tubular goods or subsurface pipe or casing may be classified as general or isolated corrosion.
A variety of problems may result from the deterioration of subsurface casing. Drill pipe collars may rub the casing, possibly leading to a blowout if the casing is allowed to become extremely worn. In a production well, deteriorated casing may permit undesirable "thiefing" of the flow to unwanted zones, thereby reducing the surface production. In an injection well, deteriorated casing may permit the injected fluid to flow to undesired formations.
Thus, it has been a long sought goal to provide accurate information concerning the condition of subsurface casing deterioration. In production wells, this information is useful when planning repairs and workovers or perforations of new intervals in already perforated casing.
A well known method of acquiring information regarding subsurface casing conditions, specifically the determination of the presence of defects in downhole casing strings has been through the use of inspection instruments such as the one described in U.S. Pat. No. 3,543,144, issued to Walters et al on Nov. 20, 1970. The basic inspection instrument consists of an electromagnet, a magnetic sensing section, and two electronic packages to process the signals from the magnetic sensing section. During operation, a steady (DC) electromagnetic field of constant strength is generated by the inspection instrument. As the tool traverses the survey interval at a constant logging speed, the electromagnetic field permeates the casing wall with magnetic lines of flux. If there is no defect in the casing, the flux lines simply pass from one of the inspection instrument's poles, through the casing, and back to the other pole. If there is a defect in the casing wall, some of the electromagnetic field generated by the inspection instrument will "leak" out of the steel casing wall and flow around the defect. To detect such leakage, the inspection instrument includes two sets of contact shoes which survey the casing wall during a logging pass. Each shoe includes two Flux Leakage (FL) coils and two Eddy Current (EC) coils; one EC coil corresponding to each FL coil.
When an FL coil detects flux leakage (indicating a defect) the companion EC coil generates a signal if the defect is on the inside casing wall. No EC signal will be generated if the defect is on the outside casing wall. At the surface, a record is made of the greastest signal from each set of shoes. These records are commonly called FL-1, FL-2 and EC respectively. Lastly, all FL signals from one set of shoes are further processed to yield a fourth recorded signal, FL AVE.
Of the four signals that can be recorded from this process, the two flux leakage signals, FL-1 and FL-2, are used to quantify the defect, or in other words, determine the percent of casing wall penetration in a defect. The third signal, EC, is used to qualify the defect to determine whether a defect is on the inside or outside of the casing wall. The fourth signal, FL AVE, is used to give an indication of the percent of the casing circumference that a defect occupies.
In order to interpret the information received from the inspection instrument and fully analyze the condition of the subsurface casing condition, considerable time and effort must be expended in the analysis of the recorded data. One problem that slows the interpretation of the data is that the structural configuration of the casing affects the existing data received from the inspection instrument. Each pipe collar, as well as hardware such as a centralizer, scratcher, or perforation, present along the casing length under inspection causes an undesirable response in the data received from the inspection instrument. These responses must be located and excluded from further analysis in order for the proper analysis of the state of casing deterioration to be made. To accomplish this analysis, visual inspection of the data provided by the inspection instrument and point-by-point comparison of the data recordings must be performed. Casing collars, centralizers, perforations and scratchers must be identified by the visual inspection of the responses of the received data and eliminated from the casing corrosion analysis.
Generally, data responses which have not been eliminated by the above described analysis are classified as defects caused by corrosion. There are two basic types of corrosion that may be present at the located defect: general corrosion and isolated corrosion. Isolated corrosion is commonly considered to be a defect or pit limited in extent to several inches in diameter vertically along the casing string as well as circumferentially around the casing. General corrosion, on the other hand, is often characterized by numerous, closely spaced defects extending over several feet vertically along the casing or circumferentially around the casing or both.
As well as being a useful indicator of the condition of subsurface casing or similar tubular goods, the discrimination between general and isolated corrosion is necessary for further corrosion analysis. A common step in the analysis of casing defects caused by corrosion is the use of the FL response, which indicates the presence of a defect, in calculating the percent casing wall penetration for that defect. Typically, this calculation is made by using the appropriate casing penetration chart. Choice of the proper casing penetration chart for this calculation is made by considering whether the corrosion present at the defect is general or isolated corrosion, whether the defect is located along the inside or the outside of the casing as well as the casing's outside diameter, weight-per-foot, and grade.